Steerable fixed cutter drill bit

ABSTRACT

A fixed cutter drill bit includes a plurality of gage pads, where certain of the gage pads have an active cutting region adjacent to the end of the gage pad adjacent to the bit face, and a passive region at the end of the gage pad adjacent to the pin-end of the bit. The active regions include forward-facing cutter elements. Other gage pads include an active region on the end adjacent to the pin-end, and a passive region on the gage pad end adjacent to the bit face. The passive and active regions have lengths within the range of 40 to 60 percent of the total axial length of the gage pads. A passive gage pad is positioned on the bit between the gage pads having both active and passive regions.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. provisional application Ser. No. 60/741,005 filed Nov. 30, 2005, and entitled “Side Cutting Drill Bit and Gage Pad Configuration,” which is hereby incorporated herein by reference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

BACKGROUND

1. Field of the Invention

The invention relates generally to earth boring drill bits. More specifically, the invention relates to fixed cutter, steerable drill bits.

2. Description of the Related Art

In drilling a borehole in the earth, such as for the recovery of hydrocarbons, minerals or for other applications, it is conventional practice to connect a drill bit on the lower end of an assembly of drill pipe sections which are connected end-to-end so as to form a “drill string.” The drill string and bit are rotated by apparatus that is positioned on a drilling platform located at the surface of the borehole. The bit may also or alternatively be rotated by means of a downhole motor that is connected to the drill string above the bit. Such apparatus turns the bit and advances it downward, causing the bit to cut through the formation material by either abrasion, fracturing, shearing, or through a combination of all cutting methods. While the bit rotates, drilling fluid is pumped through the drill string and directed out of the drill bit through nozzles that are positioned in the bit face. The drilling fluid cools the bit and flushes cuttings away from the cutting structure and face of the bit. The drilling fluid and cuttings are forced from the bottom of the borehole to the surface through the annulus that exists between the drill string and the borehole sidewall.

Many different types of drill bits with different rock removal mechanisms have been developed and found useful in drilling such boreholes. Such bits include diamond impregnated bits, milled tooth bits, tungsten carbide insert (“TCI”) bits, polycrystalline diamond compacts (“PDC”) bits, and natural diamond bits. The selection of the appropriate bit and cutting structure for a given application depends upon many factors.

Without regard to the type of bit, the cost of drilling a borehole for recovery of hydrocarbons is proportional to the length of time it takes to drill the borehole to the desired depth and location. The drilling time, in turn, is greatly affected by the number of times the drill bit must be changed in order to reach the targeted formation. This is because each time the bit is changed, the entire drill string, which may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string which must be reconstructed again, section by section. As is thus obvious, this process, known as a “trip” of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to employ drill bits that will drill faster and longer and that are usable over a wider range of differing formation hardnesses.

The length of time that a drill bit is kept in the hole before the drill string must be tripped and the bit changed depends upon a variety of factors. These factors include the bit's rate of penetration (“ROP”), its durability or ability to maintain a high or acceptable ROP, and its ability to be steered along the predetermined path or drilling program. Also important is borehole quality, as represented by the smoothness of the borehole wall created by the drill bit.

With modern drilling practices, especially important to maximizing the time that a dill bit may be kept in the hole before the drill string must be tripped and the bit changed is the bit's ability to achieve the objectives outlined by the drilling program, especially in directional applications. For example, varying formation hardnesses may dictate the need for different types of drill bits for use in different portions of the borehole. In directional applications, a particular drill bit design may be most appropriate for high dog leg applications (i.e., an application requiring relatively severe turning angles), while a different drill bit is most suited for low dog leg applications (i.e., an application requiring relatively gradual turning angles).

In recent years, the fixed cutter bit has become an industry standard for cutting formations of soft and medium hardnesses, and some hard formations. The inserts or cutter elements used in such bits are formed of extremely hard materials, which sometimes include a layer of thermally stable polycrystalline (“TSP”) material or polycrystalline diamond compacts (“PDC”). In the typical fixed cutter PDC bit, each cutter element comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of the bit body. A disk or tablet-shaped, hard cutting layer of polycrystalline diamond or thermally stable polycrystalline material is bonded to the exposed end of the support member, which is typically formed of tungsten carbide. For convenience, a fixed cutter bit employing either PDC or TSP cutter elements will be referred to in the following disclosure as a “PDC bit.”

A PDC bit may also include gage pads extending from the bit body on the sides of the drill bit. Among other purposes, gage pads may be employed to reduce vibrations experienced by the drill bit, as well as to help maintain the borehole at the desired full gage diameter. In general, vibrations are undesirable because excess vibration of the drill bit reduces the effectiveness and ROP of the drill bit, interferences with communications, and increases detrimental loads and stresses on various drill string components. A bit that experiences relatively minor vibrations is referred to as a “stable” bit. Thus, a stable PDC bit is preferred to enhance drilling effectiveness and ROP.

Side cutting is a drill bit's ability to cut the sidewall of the borehole, as contrasted to cutting the bottom of the borehole. Side cutting ability is particularly important in directional drilling applications where a drill bit must be steered to achieve different trajectories as dictated by the inclination or azimuth called for by the predetermined drilling plan or program. For example, in horizontal drilling through a pay zone (i.e., the formation layer that contains the hydrocarbons to be recovered), it is not uncommon for the pay zone to incline or decline over a portion of its length. To stay in the pay zone, or the desired portion of the pay zone, carefully controlled steering of the drill bit may be necessary. Such steering ability is greatly enhanced by employing a bit that provides substantial side wall cutting.

All PDC bits are not well suited for side cutting however, and the design of a successful side cutting drill bit is a challenge. In some applications, an ability to make quick, severe changes in drilling direction is most important, while other application may require design features making the drill bit more suited to cutting longer straight sections of the borehole, even if the drill bit's ability to make sharp turns is somewhat compromised.

Attempts to provide a bit having side cutting capability have included placing forward-facing cutter elements along the length of the bit's gage pads, rather than employing “cutterless” gage pads that simply resist wear and rub the sidewall. In addition to enhancing the side cutting capability of the drill bit, forward-facing cutter elements disposed on the bit's gage pads to engage the borehole sidewall also improves the directional maneuverability or steerability of the bit. Although forward-facing cutter elements along the length of the gage pads may allow the bit to be steered to make sharp or relatively “quick” turns, such an arrangement can result in a drill bit that requires increased torque for rotation since the side cutting cutter elements cut or bite into the borehole sidewall, particularly upon unplanned trajectory changes. Increased bit torque may lead to increased likelihood for lateral torsional excitations, vibrations, bit whirl, or combinations thereof. Excessive vibrations may place increased and undesirable loads on the drill string components, as well as detrimentally affect tool electronics and communication capabilities. Thus, many conventional steerable fixed cutter bits with forward-facing cutter elements spaced along the entire length of the gage pad may be easily steered, but tend to experience undesirable vibrations. For example, some conventional steerable bits capable of making 0-5° turns within 100 feet are highly maneuverable, but are especially more prone to severe vibrations. On the other hand, cutter less gage pads (i.e., gage pads without forward-facing cutter elements) generally require less torque to rotate, but provide reduced and limited steerability.

A “sail” is a length of borehole intended to remain constant in terms of angular trajectory or cutting path. During long sails, relatively little corrective turning is needed, provided the bit “holds angle” and does not deviate from the desired path or trajectory. Unfortunately, due to unforeseen faults, variations in formation material, or other occurrences, the bit will sometimes “lose angle” and leave the desired path. When that occurs, some correction needs to be made in order to place the bit back on the intended path. Drill bits that include aggressive side cutting features provide improved maneuverability and enable the bit to be correctively steered back onto the desired path quickly. Such aggressive side cutting bits include those having cutter elements positioned along substantially the entire length of each of the bits' gage pads, or on at least on certain of the gage pads. However, as previously described, although steerable fixed cutter bits with forward-facing cutter elements spaced along the gage pads may be easily steered, such bits tend to experience undesirable vibrations. In addition, during long sails or tangent trajectories, the aggressive side cutting features tend to cut the low-side of the borehole, making it difficult to hold angle. Further, this arrangement tends to result in the introduction of undesirable “kinks” or “irregularities” in the borehole at each change in direction, thereby decreasing borehole quality. Drilling a borehole with an undesirable number of such kinks increases the stress and forces applied to the drill string, and may lead to tools becoming stuck in the borehole or otherwise damaged. Thus, some highly maneuverable conventional bits are capable of directional changes in a short length of borehole, but they tend to create boreholes with less than desirable quality. Still further, it should also be appreciated that any damage to the forward-facing cutter elements for side cutting (e.g., due to chipping, spalling, or breakage) reduces the ability of the bit to maintain full gage diameter.

An alternative bit design calls for longer gage pads and fewer cutter elements along the gage pads' lengths, such that the PDC bit and its gage pads may be said to be less aggressive. Such a design may be highly desirable in relatively long sails where few directional changes need to be made. In addition, such bits having less-aggressive gage pad cutting structures generally require less torque to rotate, and thus, are less likely to contribute and/or excite the bit into torsional vibrations. However, when a correction does need to be made, the less aggressive bit is less responsive. Consequently, changes in direction must occur much more slowly, requiring a substantially greater length of borehole in order to affect a directional change.

Accordingly, an improved PDC bit providing good ROP and borehole quality, yet still capable of reasonable maneuverability within what might be a generally narrow pay zone would be welcome in the art. Such a bit would be particularly well received if it offered the potential to reduce vibrations experienced by the bit, effectively maintained full gage diameter, and created a relatively smooth borehole during use.

SUMMARY OF PREFERRED EMBODIMENTS

The embodiments described herein include a fixed cutter drill bit particularly suited for low dog-leg applications where modest build rates are needed. In certain embodiments, the bit includes a bit body having a bit face with a cutting structure for cutting a borehole to full gage diameter, and a pin-end opposite said bit face. The bit includes a plurality of gage pads spaced about said bit body. Certain of the gage pads include forward-facing cutter elements forming an active cutting region on an end of the gage pad that is closer to the bit face than to the pin-end, and include a passive region, without forward-facing cutter elements, located on the end of the gage pad closer to the pin-end than the bit face. The passive and active regions each have a length that is within the range of 40 to 60 percent of the length of the gage pad. In this embodiment, the bit includes a passive gage pad immediately adjacent to the gage pad having passive and active regions.

In other embodiments, the fixed cutter drill bit includes one or more additional gage pads having active and passive regions, as described above, but that are located at different positions. Specifically, in such embodiments, the drill bit includes a gage pad having forward-facing cutter elements and an active region on the end of the gage pad that is closer to the pin-end than to the bit face.

The active regions of multiple gage pads form, in rotated profile, a composite active cutting profile that has a length of approximately 50 percent of the length of the gage pads, and within the range of 40 to 60 percent of their length. Likewise, the passive regions of other of the gage pads form, in rotated profile, a composite passive cutting profile having a length of about 50 percent of the length of the gage pads, and within the range of 40 to 60 percent of the gage pads' length.

The embodiments described herein provide the maneuverability required in many applications. Although maneuverable, the bit resists vibration and produces a borehole with fewer kinks or restrictions as may be created by a drill bit that employs forward-facing cutter elements along the entire length of the bit's gage pads. Thus, the embodiments described herein comprise a combination of features providing the potential to overcome certain shortcomings associated with prior devices. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments, and by referring to the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more detailed description of the preferred embodiments, reference will now be made to the accompanying drawings, wherein:

FIG. 1 is a perspective view of a bit made in accordance with the principles as described herein.

FIG. 2 is a partial cross-sectional view of the bit of FIG. 1 with the cutter elements of the bit shown rotated into a single profile.

FIG. 3 is a schematic view showing the profiles of the various gage pads of the bit of FIG. 1.

FIG. 4 is a schematic profile view of the composite cutting profile formed by two of the gage pads of the bit of FIG. 1.

FIG. 5 is a schematic profile view of the composite cutting profile formed by another two of the gage pads of the bit of FIG. 1.

FIG. 6 is a schematic profile view of an alternative gage pad arrangement.

FIG. 7 is a schematic profile view of another alternative gage pad arrangement.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Referring to FIGS. 1 and 2, exemplary bit 10 is a fixed cutter bit, sometimes referred to as a “drag bit,” which is adapted for drilling through formations of rock to form a borehole. Bit 10 generally includes a bit body 12, a shank 13, and a threaded connection or pin 14 for connecting bit 10 to a drill string (not shown), which is employed to rotate bit 10 in order to drill the borehole. Bit 10 further includes a central axis of rotation 11 and a cutting structure 15 which, in this embodiment, includes PDC cutter elements or inserts 40 having cutting surfaces or faces 44. Bit 10 rotates about axis 11 in the cutting direction represented by arrow 18.

Body 12 includes a central longitudinal bore 17 permitting drilling fluid to flow from the drill string into bit 10. Bit body 12 further includes a bit face 20 formed on the end of the bit 10 opposite pin end 16 and which supports cutting structure 15. Body 12 is formed in a conventional manner using powdered metal tungsten carbide particles in a binder material to form a hard metal cast matrix. Alternatively, body 12 can be machined from a metal block, such as steel, rather than being formed from a matrix.

As shown in this example, bit 10 includes eight angularly spaced-apart blades 31-38, which are integrally formed as part of, and which extend from, bit body 12. Blades 31-38 extend radially across the bit face 20 and longitudinally along a portion of the periphery of the bit. It should be understood that as used herein, the term “radial” or “radially” refers to positions or movement substantially perpendicular to bit axis 11. In addition, it should be understood that as used herein, the term “axial,” “axially”, or “longitudinally” refers to positions or movement generally parallel to bit axis 11.

Referring still to FIGS. 1 and 2, blades 31-38 include blade profiles 39 on which cutter elements 40 of cutting structure 15 are mounted. Blades 31-38 are separated by grooves which define drilling fluid flow courses 19 between and along the cutting faces 44 of cutter elements 40. Bit 10 further includes gage pads 51-58 of substantially equal length L₁ that are angularly spaced about the circumference of bit 10. Gage pads 51-58 intersect and extend from blades 31-38, respectively. In general, gage pads 51-58 help maintain the size of the borehole (e.g., full gage diameter) by a rubbing action, particularly when cutter elements 40 on the bit face 20 wear slightly under gage. In addition, gage pads 51-58 also help stabilize bit 10 against vibration. In this embodiment, certain of gage pads 51-58 include generally forward-facing cutter elements or inserts 70. As used herein, “forward facing” is used to describe the orientation of a surface that is substantially perpendicular to the cutting direction of bit 10 represented by arrow 18. Forward-facing cutter elements 70 will be described in more detail below.

FIG. 2 shows a profile view of bit 10 as it would appear with all cutter elements 40, 70 rotated into a single rotated profile. As best seen in this view, blades 31-38 include blade profiles 39. Blade profiles 39 and bit face 20 may be said to be divided into three different regions 24, 25, 26. The central region of the bit face 20 is identified by reference numeral 24 and is concave in this example. Adjacent central region 24 is the shoulder or the upturned curve region 25. Next to shoulder 25 is the gage region 26, which is the portion of the bit face 20 that defines the diameter or gage of the borehole drilled by bit 10. Cutter elements 40 are disposed along each of blades 31-38 in regions 24, 25, 26. Cutter elements 40 in gage region 26 of bit face 20 extend to full gage diameter and are known in the art as “trimmer” cutter elements. Cutter elements 40 arranged in regions 24, 25 do not extend to full gage diameter. As used herein, the term “full gage diameter” may be used to describe elements or surfaces extending to the full, nominal gage of the bit diameter, and also to such elements that extend close enough to the nominal diameter of the bit to accomplish the function of the gage pad, such as elements extending to within approximately 0.050 inch of nominal or full gage diameter. As used herein, the term “nominal gage diameter” and “full gage diameter” are used interchangeably.

Referring still to FIG. 2, body 12 is also provided with downwardly extending flow passages 21 having ports or nozzles 22 disposed at their lowermost ends. The flow passages 21 are in fluid communication with central bore 17. Together, passages 21 and nozzles 22 serve to distribute drilling fluids around the cutter elements 40 for flushing formation cuttings from the bottom of the borehole and away from the cutting faces 44 of the cutter elements 40 when drilling. Each gage pad 51-58 includes a generally gage-facing surface 60 and a generally forward-facing surface 61 that intersect in an edge 62, which may be radiused, beveled or otherwise rounded. Gage-facing surface 60 includes at least a portion that extends in a direction generally parallel to bit axis 11 and extends to full gage diameter. As explained in more detail below, in some embodiments of bit 10, a portion of gage-facing surface 60 is angled, and thus slants away from the borehole sidewall. Also, as shown in FIG. 1, forward-facing surface 61 may likewise be angled relative to bit axis 11 (both as viewed perpendicular to bit axis 11 or as viewed along bit axis 11). Surface 61 is termed generally “forward-facing” to distinguish that surface from gage surface 60, which generally faces the borehole sidewall. Gage-facing surface 60 of gage pads 51-58 abuts the sidewall of the borehole during drilling.

Conventional drill bits sometimes include wear-resistant inserts embedded in the gage pads and protruding from the gage-facing surface of gage pads. These inserts, which may include diamond coatings or coatings of other super-abrasive materials, are disposed in the gage pad so as to generally face the borehole sidewall. Whether they be termed cutters or abrasion-resistant inserts or otherwise, these wear-resistant inserts are not “forward-facing” cutter elements as the term is used herein. Such wear-resistant inserts may be employed in gage-facing surface 60 of one or more gage pads 51-58. For example, as shown in FIG. 1, gage pad 51 includes two such wear-resistant inserts 100. Likewise, three wear-resistant inserts 100 are disposed in the gage-facing surface 60 of gage pad 52.

Inserts 100 are made of a harder and more wear-resistant material than the material used to form gage pads 51-58, and thus, aid in protecting the gage pads against excessive wear and abrasion. Consequently, gage pads having wear-resistant inserts such as insert 100 maintain full gage diameter for a longer period of time and tend to improve the staibilty of the bit against vibration. Although such inserts aid in maintaining the bit's stability, they are not intended to actively cut the borehole sidewall.

Certain of gage pads 51-58 include forward-facing cutter elements 70 disposed in forward-facing surface 61. More specifically, as best shown in FIG. 1, blades 51 and 57 are shown to include forward-facing cutter elements 70. The cutting surfaces or faces of cutter elements 70 extend substantially to full gage diameter and present a cutting surface to the borehole sidewall. Cutter elements 70 are active cutter elements that include cutting edges that actively shear formation material from the borehole sidewall, as distinguished from surfaces that simply rub the borehole sidewall. As described in more detail below, gage pad 51 includes forward-facing cutter elements 70 a-c while gage pad 57 includes forward-facing cutter elements 70 j-l.

Cutter elements 70 include cutting profiles that extend substantially to full gage diameter and are particularly useful in steering bit 10. In contrast to gage pads 51, 57, gage pads 52 and 58 do not support forward-facing cutter elements in this embodiment, and thus, may be described as “passive” along their entire length. The passive regions on the gage pads provide a gage protection region that extends substantially to full gage diameter, thereby aiding in maintaining full gage diameter. Such passive regions are substantially free from active cutter elements, i.e., forward-facing cutter elements having cutting faces extending to substantially full gage diameter. Thus, as used herein, the term “passive” may be used to describe gage pads, regions of gage pads, or composite profiles of gage pads that are free of forward-facing cutter elements having cutting faces extending substantially to full gage diameter. As a further illustration, a portion of the gage pad including a forward-facing cutter element whose cutting face does not extend to full gage diameter would still be a “passive” cutting region as used herein.

Certain features and operating principles of bit 10 are best understood with reference to FIG. 3 which represents gage pads 51-58 and their forward-facing cutter elements 70 in a manner in which all blades can be viewed simultaneously in schematic fashion. Reference numerals 51 _(p)-58 _(p) represent the gage pad profiles as defined by the radially-outermost surfaces of gage pads 51-58, respectively. As will be understood by reference to FIGS. 1 and 3, when bit 10 is rotated in the borehole, the gage pads 51-58 will likewise rotate and will engage a given point on the borehole sidewall in the following order: gage pad 51, followed by gage pad 52, followed by gage pad 53, and so on through gage pad 58. Thus, gage pad 51 may be described as immediately adjacent gage pad 52 (and vice versa), gage pad 52 may be described as immediately adjacent gage pad 53 (and vice versa), and so on. As used herein, the term “immediately adjacent” is used to describe the relative angular spacing or orientation of a first gage pad relative to a second gage pad, and it means that the gage pads are angularly spaced such that there are no gage pads between the first and second gage pad.

As shown in FIG. 3, gage pads 51, 53, 55 and 57 each include forward-facing cutter elements 70, while gage pads 52, 54, and 56 do not include forward facing cutter elements. In this embodiment, elements 70 are substantially the same as elements 40 previously described. Each forward-facing cutter element 70 comprises an elongated and generally cylindrical support member or substrate which is received and secured in a pocket formed in the surface of the gage pad. A disk or tablet-shaped, hard cutting layer of polycrystalline diamond or other superabrasive material is bonded to the exposed end of the support member. The PDC elements are mounted so that their cutting faces generally face in the direction of bit rotation 18 (i.e., forward-facing).

Referring still to FIG. 3, each gage pad 51-58 has an axial length L₁ (i.e., gage pad length L₁). As best shown in FIGS. 2 and 3, gage pad length L₁ is generally measured axially from gage region 26 to the end of the gage pad that is distal to face 20. Although each gage pad 51-58 in the exemplary embodiment illustrated in FIG. 1 has substantially the same gage pad length L1, in other embodiments, two or more gage pads may have the same or different gage pad lengths. Reference plane 80 generally divides each gage pad 51-58 into a face-side half or portion 81 and a pin-side half or portion 82, with portions 81 and 82 each having a length of approximately one-half L₁. It is to be understood that face-side portion 81 is proximal face 20 (i.e., face-side portion 81 is closer to face 20 as compared to pin-side portion 82), while pin-side portion 82 is distal face 20 (i.e., pin-side portion 82 is farther from face 20 as compared to face-side portion 81).

Gage pads 51 and 55 each include three cutter elements 70 positioned in face-side portion 81. Similarly, gage pads 53 and 57 each include three forward-facing cutter elements 70 positioned in pin-side portion 82. In general, the regions or portions of the gage pads 51-58 having forward-facing cutter elements 70 retained therein are described herein as being “active” regions or “active” cutting regions. Thus, gage pads 51 and 55 may be described as including face-side active regions 72 that are closer to the bit face 20 than to pin-end 16. Similarly, gage pads 53 and 57 include pin-side active regions 73 that are closer to the pin-end 16 than to bit face 20. As used herein, the term “active” refers to gage pads or regions of gage pads that include forward-facing cutter elements whose cutting faces extend substantially to full gage diameter.

Referring still to FIG. 3, the regions of gage pads 51-58 having no forward-facing cutter elements are referred to herein as “passive” cutting regions. Gage pads 51 and 55 form pin-side passive regions 75 that are closer to the pin-end 16 of bit 10 than to the bit face 20. Gage pads 53 and 57 form face-side passive regions 74 that are closer to the bit face 20 than to pin-end 16. Although the face side active regions 72 on gage pads 51 and 55 have approximately the same length in this example, their lengths need not be identical. Likewise, the lengths of pin-side active regions 73 on gage pads 53, 57 need not be identical. Active regions 72, 73 and passive regions 74, 75 preferably have lengths between approximately 40 percent and 60 percent of the length L₁ of their respective gage pads. In this example, gage pads 51-58 have a uniform length L₁, but the length of gage pads 51-58 may differ in other embodiments. Gage pads 52, 54, 56 and 58 have no forward-facing cutter elements in this example of bit 10, and therefore include passive regions along their entire length L₁.

Referring still to FIG. 3, and comparing the profiles for gage pads 51 and 55, it will be noted that the position of cutter elements 70 g,h,i of gage pad 55 are axially offset from the positions of cutter elements 70 a,b,c of gage pad 51. In this way, as bit 10 rotates, cutter elements 70 a-c and 70 g-i will present a composite cutting profile that completely spans the face-side portion 81. This can best be seen in FIG. 4 in which gage pads 51 and 55 are shown in rotated profile. As shown, the composite profile PI of gage pads 51 and 55 present a composite active face-side region 84 having length L₂. In this embodiment, L₂ is approximately 55 percent of L₁. It should be understood that, in other embodiments, L₂ may be approximately 50 percent of L₁, or either greater or lesser than 50 percent of L₁. In most applications, L₂ should be between 40-60 percent of L₁.

Referring again to FIG. 3, gage pads 53 and 57 each include three cutter elements 70 that are slightly spaced apart so as to form the composite rotated profile shown in FIG. 5. As shown, the composite profile P₂ created by gage pads 53 and 57 create a composite active pin-side region 86. Composite active pin-side region 86 is disposed farther from the bit face 20 than composite active face-side region 84 previously described and created by gage pads 51, 55. Composite active pin-side region 86 is shown to have a length L₃ that is approximately 55 percent of L₁ in this embodiment. In other examples, length L₃ of composite active region 86 will be approximately 50 percent of L₁, or greater or less than 50 percent of L₁, and will typically be within the range of 40-60 percent of L₁.

In the embodiment thus described with reference to FIGS. 3-6, the composite active face-side region 84 formed by active regions 72 of gage pads 51 and 55 has a length L₂ of approximately 55 percent of the length L₁ of each gage pad 51, 55. Accordingly, the composite profile formed by the passive regions 75 of gage pads 51, 55 has a length of approximately 45 percent of the gage pad length L₁. Likewise, the composite active pin-side region 86 formed by active regions 73 of gage pads 53 and 58 has a length equal to approximately 55 percent of the total length of the gage pad L₁, and the composite profile formed by passive regions 74 of gage pads 53 and 58 will have a length L₃ that is approximately 45 percent of L₁. As will thus be understood, the composite active regions 84 and 86 in this example overlap by approximately 5 percent of the gage pad length L₁. While a certain degree of overlap between composite active regions 84, 86 may be desirable, that degree of overlap is preferably less than 10 percent of the gage pad length L₁.

In general, the greater the length of the active cutting region of a gage pad (i.e., the greater the percentage of gage pad length L₁ occupied by the active cutting region), the more aggressive the side cutting ability of the bit and the more maneuverable the bit (i.e., the greater the ability of the bit to turn more quickly over a shorter length of borehole). However, longer active cutting regions tend to make the bit more susceptible to torsional excitation and undesirable vibrations. In addition, longer active cutting regions may impair the ability of the bit to maintain full gage diameter in the event one or more forward-facing cutter elements (e.g., cutter elements 70) becomes damaged (e.g., chips, spalls, or breaks), and further, may reduce the ability of the bit to hold angle over long sails and straight trajectories. In the embodiments illustrated in FIGS. 1-5, if gage pads 51, 53, 55, 57 include active cutting region 72, 73 having length greater than 60 percent of gage pad length L₁, bit 10 may become more aggressive than desired. Thus, active cutting regions 72, 73 of gage pads 51, 53, 55, 57 are prefereably less than or equal to 60 percent of the gage pad length L₁.

Bit 10 may also be described as including a plurality of gage pads that are arranged in pairs. The first of the pair (gage pad 51 for example) includes an active region 72 that is closer to the bit face 20 than to the pin end 14, and the other of the pair (pad 53 in this example) includes an active region 73 that is closer to the pin end 14 of bit 10 than to bit face 20. Disposed between the pair of gage pads having active cutting regions, bit 10 includes a passive gage pad (pad 52 in this example) having no forward-facing cutter elements and thus no active region.

Embodiments of drill bit 10 as shown and described with reference to FIGS. 1-5 provide a desirable compromise between maneuverability, stability, and vibration control. In particular, embodiments of bit 10 provide adequate maneuverability for applications requiring a modest build rate (for example, less than 5°) and does so with substantially less vibration in comparison, for example, to bits having forward-facing cutter elements along the entire length of the bit's gage pads. Bit 10 is capable of providing modest corrections needed to stay within many well profiles, but makes these corrections at a slower rate (over a longer distance) than a bit having forward-facing cutter elements disposed along most or substantially all of the gage pads' length. For example, embodiments of bit 10 are intended to achieve a modest dog leg severity (DLS) of 10° or less per 100 feet. Because a fast build rate is not a requirement for bit 10, fewer cutters are required on the gage pads and less vibration is experienced. In addition, since embodiments of bit 10 include gage pads having passive regions passive (e.g., gage pad 51 with pin-side passive region 75) or that are entirely passive, (e.g., gage pads 52), bit 10 offers the potential for additional improvements over conventional bits that include side cutting features or cutter elements along the entire length of the gage pad. For instance, by reducing vibrations, as well as the amount of positive engagement or “biting” of the borehole sidewall, embodiments of bit 10 offer the potential to hold angle better during long sails and straight trajectories as compared to more aggressive side cutting bits. Still further, embodiments of bit 10 offers the potential for improved maintenance of full gage diameter since the passive regions of gage pads and entirely passive gage pads do not include cutter elements that may become chipped or otherwise damaged.

Accordingly, embodiments of bit 10 provide the bit designer the capability of having relatively long gage pads with passive regions as desirable for long sails where the bit does not change build angle. Most conventional bits employing relatively long pads without forward-facing cutter elements are ideally suited for long sails and generally experience reduced vibrations, but are typically not as maneuverable as desired. By providing the arrangement of forward-facing cutter elements 70 in selected positions on certain gage pads of bit 10 as described above, embodiments of bit 10 provide relatively long gage pads having passive regions and associated benefits, and also offers the potential for modest but sufficient build rate, steering, and maneuverability. The relatively long gage pads 51-58 of bit 10 described with reference to FIGS. 1-5 including passive regions enables bit 10 to stay on course, thereby reducing the need for numerous steering corrections, while forward-facing cutter elements 70 on selected gage pads 51-58 provide the capability for making modest corrections when required. In addition, by limiting the location of forward-facing cutter elements 70 to selected gage pads 51-58 and selected positions to enhance the ability of bit 10 to stay on course, thereby minimizing the need for steering corrections, bit 10 offers the potential for a smoother wellbore (i.e., fewer kinks) resulting in less drag and friction on the drill string and drilling tools.

The gage-facing surface 60 of gage pads 51-58 may extend generally parallel to bit axis 11 and the borehole wall along its entire longitudinal length as, for example, shown with respect to gage pads 52, 54, 56 and 58. Alternatively, portions of the gage-facing surface 60 of gage pads 51-58 may be angled or tapered relative to bit axis 11. For example, referring to the representation of gage pad 51 shown in FIG. 3, gage-facing surface 60 in the region 72 closest to bit face 20 is angled or tapered relative to the bit axis 11. In this example, angled portion 64 of gage-facing surface 60 is disposed at an angle of approximately 10 degrees relative to the bit axis 11. In other examples, this angle may vary, and typically will be between about 7-10°. Similarly, gage pad 55 includes an angled surface 65 that is generally the mirror image of surface 64 of gage pad 51 and that also tapers at approximately 10° relative to bit axis 11. Gage pads 53, 57 include angled portions 66, 67, respectively, which also taper relative to the bit axis 11 at an angle of approximately 10°; however, in this embodiment, surfaces 66, 67 taper in the opposite direction relative to tapered surfaces 64, 65. However, including tapered gage-facing surfaces such as angled portions 64-67 is not a requirement and, in other embodiments, the gage pads of the bit may have gage-facing surfaces 60 that are substantially parallel to bit axis 11 throughout their entire length.

The cutter elements 70 a-c on gage pad 51 include cutting faces of non-uniform size. Specifically, as shown in FIGS. 3, 4, the cutting face of element 70 a is larger than the cutting face of cutter element 70 b and c. Likewise, the cutting face of cutter element 70 b is larger than the cutting face of cutter element 70 c. Cutter elements 70 a-c have cutting faces that extend to full gage diameter, with the smaller cutter element 70 c being disposed closest (i.e., proximal) to plane 80 in this embodiment, and the cutter element 70 a having the largest cutting face being disposed on gage-facing surface 60 at a position closest to bit face 20. The cutter elements 70 g-i for gage pad 55 have cutting faces that also vary in size, but each extends to full gage diameter. Specifically, cutter element 70 g with the largest cutting face is disposed on gage-facing surface 60 proximal face 20 in this embodiment, while cutter element 70 i with the smallest cutting face is disposed on gage-facing surface 60 distal face 20. It is to be understood that the size of a cutting face may be determined based on the surface area of the cutting face, the diameter or radius of the cutting face in the case the cutting face is circular, or combinations thereof. As shown in FIGS. 3 and 4, the position of cutter elements 70 g-i are axially offset slightly from the positions of cutter elements 70 a-c so as to leave substantially no uncut portion of the borehole sidewall that comes into engagement with the composite active face-side region 84.

Referring to the cutter arrangement on gage pad 53, the cutter element having the smallest cutting face 70 d is closest to plane 80, while the cutter element 70 f having the largest cutting face is furthest from (i.e., distal) plane 80 and is closest to pin 14. Cutter element 70 e with a cutting face smaller than that of 70 f but larger than that of 70 d is disposed between cutter elements 70 d and 70 f. The cutter elements 70 j-l of gage pad 57 are arranged so as to be offset slightly from the positions of cutter elements 70 d-f of gage pad 53, thereby leaving substantially no uncut portion of borehole sidewall that comes into engagement with the composite active pin-side region 86.

The gage-facing surfaces 60 of gage pads 51, 53, 55, 57 may include active regions which are configured differently than that shown in FIGS. 3-5. For example, referring to FIG. 6, an alternative arrangement for a gage pad 51 having active region 72 and passive region 75 is shown. In this embodiment, gage-facing surface 60 includes a portion 68 extending to full gage diameter and forming passive region 75. The gage-facing surface 60 includes a portion 69 that is set back from gage but is substantially parallel to the portion 68 and to the bit axis 11. In this example, active region 72 supports three cutter elements 70 m,n,o having identically sized cutting faces that extend the full gage diameter.

As a further example, the gage-facing surface may include an active region that is sloped in a direction opposite that shown for gage pad 51 in FIG. 3. More specifically, and referring to FIG. 7, in this embodiment, the gage pad includes a gage-facing surface 60 divided into an active region 72 and passive region 75. Passive region 75 extends to full gage diameter along its entire length. Active region 72 includes a portion 90 of gage-facing surface 60 that tapers from a point 91 at full gage diameter to a point 92 that is offset some distance from full gage diameter. In this arrangement, the cutter elements shown 70 p,q,r are arranged such that the cutter element 70 r having the largest diameter is adjacent to the passive region 75 and nearest to plane 80, while the cutter element 70 p having the smallest diameter is furthest from plane 80 and furthest from passive region 75. According to the examples shown above, it should be understood that the principles disclosed herein may be employed with cutter elements of varying sizes, and with the gage-facing surfaces in the active region being tapered or substantially parallel to the bit axis.

Although many factors will determine the arrangement of cutter elements 70 on the gage pads, the arrangement shown in FIG. 6 may be best suited for relatively soft formations, and the arrangement shown in FIG. 3 generally suitable for a wider range of formation hardnesses.

Bit 10 described above includes eight gage pads including four that include both active and passive regions; however, employing fewer than eight gage pads can still produce a steerable bit having an acceptable build rate and vibration level for at least certain formations and conditions. For example, a six bladed bit having only gage pads 51-56 as described previously with respect to FIG. 3, would be steerable even lacking gage pad 57, which may be described as the companion gage pad to gage pad 53, and lacking passive gage pad 58.

Likewise, a four bladed bit having only gage pads 51-54 as described in FIG. 3 may provide the desirable maneuverability and diminished vibration; however, without gage pads 55, 57 as companion pads to gage pads 51, 53, respectively, a bit employing only pads 51-54 will tend to turn slower than bit 10 having gage pads 51-58.

While preferred embodiments of this invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit or teaching of this invention. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the system and apparatus are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims which follow, the scope of which shall include all equivalents of the subject matter of the claims. 

1. A drill bit for drilling a borehole having a predetermined full gage diameter, the bit comprising: a bit body having a bit face with a cutting structure thereon, and a pin end opposite the bit face; at least a first and a second gage pad positioned on the bit body between the bit face and the pin end, wherein the second gage pad is angularly spaced apart from the first gage pad; wherein the first gage pad comprises a first axial length, an active region including a plurality of generally forward-facing cutter elements having cutting surfaces extending substantially to full gage diameter, and a passive region including a gage-facing surface extending substantially to gage diameter, wherein each of the active and passive regions has a length between 40 and 60 percent of the first axial length; and wherein the second gage pad comprises a second axial length, a gage-facing surface extending substantially to full gage diameter, and a passive cutting region along substantially all of the second axial length.
 2. The drill bit of claim 1 wherein the length of the active region of the first gage pad is within the range of 45-55 percent of the first axial length.
 3. The drill bit of claim 1 wherein the active region of the first gage pad is positioned proximal the bit face.
 4. The drill bit of claim 1 wherein the active region of the first gage pad is positioned proximal the pin-end.
 5. The drill bit of claim 1 wherein the first gage pad is disposed at an angular position immediately adjacent the second gage pad.
 6. The drill bit of claim 1 wherein the cutting surface of each forward-facing cutter element has a cutting face surface area, wherein at least two of the forward-facing cutter elements have cutting surfaces with different cutting face surface areas.
 7. The drill bit of claim 1 wherein the active region of the first gage pad includes a gage-facing surface and wherein the gage-facing surface of the active region and passive region of the first gage pad are substantially parallel to the bit axis.
 8. The drill bit of claim 1 wherein the active region of the first gage pad includes a gage-facing surface including a tapered portion oriented at an angle between 0° and 10° relative to the bit axis.
 9. The drill bit of claim 8 wherein the tapered portion is oriented at an angle between 7° and 10° relative to the bit axis.
 10. A drill bit for forming a borehole in earthen formations, the bit comprising: a bit body having a bit axis, a bit face, and a pin end opposite the bit face; a plurality of gage pads having first and second ends and disposed about the bit body at angularly spaced-apart positions, the first end of each gage pad being closer to the bit face than to the pin end; a first of the plurality of gage pads having a length and comprising an active region including a plurality of forward-facing cutter elements and a passive region, each of the active and passive regions of the first gage pad having a length of at least 40 percent of the length of the first gage pad; and a second of the plurality of gage pads disposed at an angular position immediately adjacent to the first gage pad, the second gage pad having a length and comprising a passive region along substantially the entire length of the second gage pad.
 11. The drill bit of claim 10 wherein the active region of the first of the plurality of gage pads is positioned adjacent the first end of the first gage pad and wherein the passive region of the first of the plurality of gage pads is positioned adjacent the second end of the first gage pad.
 12. The drill bit of claim 11 further comprising: a third of the plurality of gage pads disposed at an angular position immediately adjacent to the second gage pad such that the second gage pad is disposed between the first and third gage pads, the third gage pad having a length and comprising an active region including a plurality of forward-facing cutter elements adjacent to the second end of the third gage pad and a passive region adjacent to the first end of the third gage pad, the active and passive regions of the third gage pad each having a length of at least 40 percent of the length of the third gage pad.
 13. The drill bit of claim 12 further comprising a fourth gage pad disposed at an angular position immediately adjacent to the third gage pad such that the third gage pad is disposed between the second gage pad and the fourth gage pad, the fourth gage pad having a length and comprising a passive region along substantially the entire length of the fourth gage pad.
 14. The drill bit of claim 10 wherein the active region of the first of the plurality of gage pads is positioned adjacent the second end of the first gage pad and wherein the active region of the first of the plurality of gage pads is positioned adjacent the second end of the first gage pad.
 15. The drill bit of claim 14 further comprising: a third of the plurality of gage pads disposed at an angular position immediately adjacent to the second gage pad such that the second gage pad is disposed between the first and third gage pads, the third gage pad having a length and comprising an active region including a plurality of forward-facing cutter elements adjacent to the first end of the third gage pad and a passive region adjacent to the second end of the third gage pad, the active and passive regions of the third gage pad each having a length of at least 40 percent of the length of the third gage pad.
 16. The drill bit of claim 15 further comprising a fourth gage pad disposed at an angular position immediately adjacent to the third gage pad such that the third gage pad is disposed between the second gage pad and the fourth gage pad, the fourth gage pad having a length and comprising a passive region along substantially the entire length of the fourth gage pad.
 17. The drill bit of claim 10 wherein each of the forward-facing cutter elements of the active region of the first gage pad extends substantially to a predetermined full gage diameter.
 18. The drill bit of claim 10 wherein the first and second of the plurality of gage pads each includes a gage-facing surface including at least a portion that extends substantially to a predetermined full gage diameter and is substantially parallel to the bit axis.
 19. The drill bit of claim 15 wherein the gage-facing surface of the first of the plurality of gage pads comprises a tapered portion oriented at angle between 0° and 10° relative to the bit axis.
 20. A drill bit for cutting a borehole at a predetermined full gage diameter, the bit comprising: a bit body having at least eight gage pads disposed about the body at angularly spaced-apart positions; a bit face on the bit body, the bit face comprising a cutting structure cutting the borehole to the full gage diameter; a pin end on the bit body opposite the bit face; wherein a first and a second of the gage pads each comprises a plurality of forward-facing cutter elements forming an active cutting region that is closer to the bit face than to the pin end, and a passive region closer to the pin end than to the bit face; wherein a third and a fourth of the gage pads each comprises a plurality of forward-facing cutter elements forming an active cutting region that is closer to the pin-end than to the bit face, and a passive region that is closer to the bit face than to the pin-end; wherein the gage pads are angularly spaced about the bit such that each of the first and second gage pads is disposed at a location that is between the third and fourth gage pads; and wherein four other of the at least eight gage pads includes only a passive cutting region.
 21. The drill bit of claim 20 wherein one of the four other gage pads is angularly positioned between two of the gage pads having the active and passive regions.
 22. The drill bit of claim 20 wherein each of the forward-facing cutter elements of each active region extend substantially to the predetermined full gage diameter.
 23. The drill bit of claim 20 wherein each of the eight gage pads includes a gage-facing surface having at least a portion that extends substantially to the predetermined full gage diameter.
 24. A drill bit for drilling through earthen formations and forming a borehole of a predetermined full gage diameter, the bit comprising: a bit body; a bit face on the body having a cutting structure for cutting the borehole to full gage diameter; a pin end on said body opposite the bit face; a plurality of gage pads angularly spaced about the bit body, each gage pad having a length; wherein at least a first and a second of the gage pads each comprise forward-facing cutter elements that are positioned closer to the pin end than to the bit face, the first and second gage pads forming a first composite active cutting profile having a length equal to between 40 and 60 percent of the length of the first gage pad, the first composite active cutting profile being located closer to the pin end of the bit than to the cutting face; wherein each of the first and second gage pads further includes a passive cutting region positioned at a location closer to the bit face than to the pin end and forming a first composite passive cutting profile having a length of between 40-60 percent of the length of the first gage pad; and a third gage pad disposed at an angular position between the first and second gage pads, wherein the third gage pad is passive.
 25. The drill bit of claim 24 further comprising: a fourth gage pad disposed an angular position between the first and third gage pads, wherein the fourth gage pad is passive.
 26. The drill bit of claim 25 further comprising: a fifth gage pad comprising forward-facing cutter elements forming an active cutting region that is closer to the bit face than to the pin end, and further comprising a passive region that is closer to the pin end than to the bit face; and wherein the fifth gage pad is disposed an angular position between the third and fourth gage pad.
 27. The drill bit of claim 24 further comprising a fourth and a fifth gage pad, each comprising forward-facing cutter elements that are positioned closer to the bit face than to the pin-end, the fourth and fifth gage pads forming a second composite active cutting profile having a length between 40 and 60 percent of the length of the first gage pad, the second composite active cutting profile being located closer to the bit face than to the pin-end; wherein each of the fourth and a fifth gage pads further comprises a passive cutting region positioned at a location closer to the pin-end than to the bit face, and forming a second composite passive cutting profile having a length between 40 and 60 percent of the length of the first gage pad.
 28. The drill bit of claim 27 wherein each of the fourth and a fifth gage pads is positioned at a different angular position, and positioned at an angular position that is between the first and second gage pads.
 29. The drill bit of claim 28 wherein the bit further comprises at least one passive gage pad located at an angular position between each of the first, second, fourth and fifth gage pads.
 30. The drill bit of claim 27 wherein the first composite active cutting profile overlaps with the second composite active cutting profile by no more than 10 percent of the length of the first gage pad. 